Treatment fluid composition for high temperature multi-stage fracturing applications

ABSTRACT

Provided is a method that may include introducing into a wellbore as a single stage treatment a composition that may include a fluid formulation that is a water-in-oil emulsion having an organic phase and an aqueous phase, the aqueous phase dispersed in the organic phase; maintaining the wellbore by shutting-in the well; and hydraulic fracturing the wellbore. The composition may contain a chelating agent and may interact with an oil-based sludge or filter cake, which may contain barite, at a target zone, allowing the composition to remove a portion of the oil-based mud sludge or filter cake.

BACKGROUND

In the oil and gas industry, fracturing is a common technique used tostimulate a petroleum-bearing rock formation and recover oil and gasthrough a wellbore. These fracturing techniques use a variety of fluids,including fracturing fluid and drilling fluid.

Drilling fluids are used to help drill wellbores into earth formations.Drilling fluids may be used to cool the drilling equipment, reducefriction between the drill bit and the wellbore surface, control theformation pressure, seal permeable formations, and maintain wellborestability. Drilling fluids may create a hydrostatic pressure preventingfluids in the formations from penetrating a wellbore. Drilling fluidsmay include a weighting material that forms a sludge composed of organicmatter, oil, drilling cuttings, and solid particles. Weighting materialsare generally the main solid constituent of drilling fluids. Barite isoften used to increase the weight and hydrostatic pressure of drillingfluids.

When oil-based mud (OBM) is used as a drilling fluid, sludge from theOBM can deposit in and around the wellbore. This OBM sludge can resultin formation of “filter cake” or “mud cake” that comprises bariteparticles. Such filter cake is impermeable and highly insoluble in bothwater and acidic solutions, such as solutions of acetic acid,hydrochloric acid, and formic acid. A particular place that sludge candeposit is on formation entry points, where a fracturing mechanismintroduces perforations into the formation. The sludge that deposits onformation entry points and resultant filter cake has the potential toresist fracturing. In some fracturing operations, such as hydraulicfracking, a buildup of sludge or filter cake may prevent fracturing fromoccurring as designed. When the buildup resists or prevents fracturing,the fracturing operation is compromised.

At completion of the drilling and before hydraulic fracking, the sludgeor filter cake must be removed to allow production of the formationfluids or bonding of cement to the formation at the completion stage.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In one aspect, provided is a composition that may include a fluidformulation that is a water-in-oil emulsion, having an organic phase andan aqueous phase, the aqueous phase dispersed in the organic phase. Theorganic phase may include an organic solvent, an emulsifier, and awetting agent. The aqueous phase may include water and a chelatingagent.

In another aspect, provided is a method that may include introducing acomposition that is a water-in-oil emulsion into a wellbore as a singlestage treatment such that it fluidly interacts with an oil-based mudsludge or a filter cake having barite at a target zone. The water-in-oilemulsion may have an organic phase and an aqueous phase. The organicphase may include an organic solvent, an emulsifier, and a wettingagent. The aqueous phase may include water and a chelating agent. Thetarget zone may have a deposit of oil-based mud sludge or filter cakehaving barite. The method may also include maintaining the wellbore byshutting-in the well and allowing the composition to penetrate theoil-based mud sludge or filter cake having barite in a target zone,thereby allowing the composition to remove a portion of the oil-basedmud sludge or filter cake having barite. The method may further includehydraulic fracturing the wellbore.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to well treatmentfluid compositions. The composition is a water-in-oil (w/o) emulsion ofan organic solvent and an aqueous solution. The aqueous solutionincludes a chelating agent and has a “high pH,” defined as a pH from10-14. Stability of the emulsion is provided by use of a fattyacid-based emulsifier and a wetting agent.

In another aspect, a method of introducing the composition downhole in acleanout operation is provided. The composition may be introduced aheadof a fracturing operation. In this way, sludge deposition that resistsfracture initiation can be stimulated. The composition may stimulate anoil-based mud (OBM) sludge or filter cake. Stimulation may includepenetration of the composition into a material. The filter cake may be adeposition from oil-based drilling fluid, OBM sludge, which may includebarite particles and organic matter. These types of filter cake arecommonly known in the art. The treatment method may provide a cleanoutoperation ahead of hydraulic fracturing by enhancing injectivity at thefracturing entry points.

Stimulation of the sludge deposition may provide for dissolution orremoval of sufficient sludge for fracture initiation and successfulfracturing operations, including multi-stage fracturing operations.Depending upon the composition of the sludge, treatment fluids hereinmay remove a majority of the sludge, and approximately 100 weight % (wt%) of the sludge in some embodiments. In one or more embodiments,stimulation by the composition may not dissolve the deposited sludge orfilter cake completely; treatment fluids herein have been found toremove up to 40 wt %, up to 50 wt %, up to 60 wt %, up to 70 wt %, up to80 wt %, or up to 90 wt % of a barite/oil-based mud sludge, for example.With this amount of sludge removal, passage of fracturing fluids throughthe treated sludge deposit or filter cake are sufficient to initiate afracture (namely, through a fracture port) and provide for a successfulfracturing operation.

Acid stimulation is a typical treatment used before multi-stagefracturing to remove deposited materials on formation, thereby,facilitate fracture initiation.

A main source of solids in an OBM filter cake are “barite particles,”which means particles that include barium. Thus, barite particles arenot limited to barite itself (BaSO₄), and may include barium salts,salts including barite, organometallic complexes including barium,organometallic complexes including barite, barium and barite alloys,barium and barite-based minerals, and the like. Barite is well known asa common weighting material used in drilling fluids for oil and gaswells. These drilling fluids may develop sludge in oil and gaswellbores, prior to fracturing operations. The oil-based mud sludge mayinclude organic matter, OBM oil, barite particles, drilling cuttings,other solids, and intractable materials. The sludge may include asubstantial amount of organic materials, such as in a range of from 40to 60 wt % compared to the weight of the overall sludge composition, butthe range is not limited thereto.

OBM having barite or OBM having barite particles may be called abarite-based OBM sludge. When the barite-based OBM sludge is hardened,it may form a filter cake. Likewise, filter cake having barite may becalled a barite-based filter cake.

In general, scales including barite particles are pervasive and aredifficult to remove, in part due to low solubility of barite in water.Barite's low solubility is about 2 milligrams per liter (mg/L). Baritemay also be insoluble in aqueous fluids having a low pH, such as pH ofless than 7, 6 or less, 5 or less, or 4 or less that may includehydrochloric acid (HCl), formic acid, citric acid, acetic acid, andother acids that may be commonly added to wellbore fluids, such as acidstimulation fluids. However, barite is moderately soluble in aqueoussolutions that include chelating agents.

A chelating agent (derived from the Greek root of the Latin word chele,or “claw-shaped mechanism”) is a molecule that includes two or moreligands with an ability to form coordinate covalent or ionic bonds witha target atom or molecule inside the ligand. These ligands effectivelyclamp (or claw) the target atom or molecule, with greater effectivenessthan if the target atom or molecule were sequestered by electrostaticshielding without chelation. This clamping of the target atom ormolecule is known in the art as a ligand field. The target atom ormolecule may be a metal, an ion, an inorganic compound, an organiccompound, or an organometallic compound. The target atom or molecule isoften a metal or a salt thereof. In one or more embodiments, a targetmolecule for chelation includes barite particles.

Barite is moderately soluble in chelating agents such asethylenediaminetetraacetic acid (EDTA) and diethylenetriaminepentaaceticacid (DTPA, or pentetic acid). Aqueous solutions including EDTA and DTPAmay have a “high pH,” meaning a pH of 10-14.

High pH fluids, however, have been found to be ineffective withoil-based mud sludge, as organic matter covering the surface of bariteacts as a reaction barrier. Organic materials are insoluble in aqueoussolutions and tend to dissolve well in solvents that have similarproperties. However, high pH aqueous solutions (for example, DTPA-basedand EDTA-based solutions) and organic solvents (for example,hydrocarbons) are not miscible. Because of this issue, in pastmethodologies, two stage treatments have been used. A two stagetreatment may provide a first treatment stage to remove the organicmatter and a second treatment stage to dissolve a portion of the baritematerials. In contrast to these methods, embodiments herein provide aone-stage treatment fluid that may be used to both effectively removeorganic materials and dissolve barite materials.

Treatment fluids according to embodiments herein, useful for one-stagetreatment of barite/OBM sludge, may include an organic phase and anaqueous (non-organic) phase, emulsifying an organic solvent and a highpH chelating agent, as will be described further below. With use offluids according to embodiments herein, sludge deposition that restrictsfracture initiation during MSF (multi-stage fracturing) can bestimulated and penetrated. Such treatment may assure effective cleanoutoperation ahead of MSF to improve hydraulic fracturing effectiveness byenhancing injectivity, as compared to without treatment. Chemicaltreatment may also target the frac ports and not the entire wellbore.Overall, a one-stage treatment fluid may reduce chemical volumes andthus treatment costs, as compared to a multi-stage treatment.

A typical MSF completion may include wellbore casing and liner extendingdownward into the wellbore. The wellbore may include a wellbore isolatorthat may be a ball-actuated sliding sleeve or similar mechanism. Thewellbore isolator can be run inside the liner or in the open hole. Themechanism of the isolator is known in the art. The wellbore may bevertical or horizontal. The production liner of an MSF completionincludes a series of alternating isolation packers and frac ports, oneafter the other.

Well Treatment Compositions

In one or more embodiments, the well treatment composition according toembodiments herein is a fluid formulation that is an emulsion. In one ormore embodiments, the emulsion is a water-in-oil (w/o) emulsion with acontinuous organic phase and a dispersed aqueous phase. The organic andnon-organic phases may be effectively stabilized by using an emulsifierand a wetting agent. Thus, the well treatment composition according toembodiments herein may be an emulsion including an aqueous phase, anorganic phase, an emulsifier, and a wetting agent. In other embodiments,the well treatment composition according to embodiments herein may be anemulsion, such as a water-in-oil emulsion, where the organic phaseincludes an organic solvent, an emulsifier, and a wetting agent, and theaqueous phase includes water and a chelating agent. In one or moreembodiments, the well treatment composition may further include aconverting agent, and oxidizer or enzymes.

In one or more embodiments, the ratio between organic solvent and thechelating agent in the composition will be 20:80 or 30:70 volumetricratio (organic: aqueous phase).

One or more embodiments of the well treatment composition is awater-in-oil emulsion that may retain stability up to 96 hours at 20° C.to 30° C., such as 25° C. For example, the emulsion may retain stabilityfrom 1 to 96 hours, 12 to 96 hours, 24 to 96 hours, 36 to 96 hours, 48to 96 hours, 60 to 96 hours, 72 to 96 hours, or 84 to 96 hours.

In one or more embodiments, the well treatment composition has nooverall pH value. The aqueous phase in the water-in-oil emulsions hereinmay be defined by a pH value, but the organic phase (oil phase) and theoverall water-in-oil emulsion is not defined by a pH value.

The density of the well treatment composition may vary based onconcentration of the components therein. The density may be as low as0.8 grams per centimeter cubed (g/cm³) for the organic phase, and ashigh as 1.17 g/cm³ for the aqueous phase. The overall density of thewell treatment composition may be as high as 1.03 g/cm³. Densities aremeasured herein at room temperature, such as between temperatures ofabout 20 to 30° C. In some embodiments, densities may be defined asabove for a temperature of 25° C.

The viscosity of the well treatment composition may vary based onconcentration of the components therein. The viscosity of thecomposition may range from 50 to 500 centipoise (cP), such as from 80 to200 cP. The upper range is not particularly limited and may be greaterthan 200 cP.

In one or more embodiments, the composition does not include ademulsifying agent. A demulsifying agent, as the name implies, willbreak up the emulsion, and embodiments of treatment fluid compositionsherein may lose stability when a demulsifying agent is introduced in arange from 0.3 to 2 vol %, such as at 0.6 vol %.

In one or more embodiments, the composition does not include mutualsolvent. A mutual solvent has also been found to destabilize embodimentsof the emulsions disclosed herein. “Destabilize” in this instance meansthat an emulsion will not develop where a mutual solvent is use, or thatthe emulsion will be broken when using a mutual solvent. Examples ofmutual solvents include, but are not limited to, ethylene glycolmonobutyl ether (2-butoxyethanol), diethylene glycol butyl ether, andother modified glycol ethers.

Aqueous Phase

The aqueous phase of well treatment compositions according to one ormore embodiments herein may include an aqueous solution comprising achelating agent. The aqueous solution of yet other embodiments mayinclude the chelating agent, water barite converting agent, enzyme,oxidizer, and optionally one or more additional components.

In one or more embodiments, the aqueous phase is in a volume range offrom 30 to 90 volume percent (vol %) compared to the overall compositionvolume. For example, the aqueous phase may be in a range of from 40 to90 vol %, 50 to 90 vol %, 55 to 85 vol %, 60 to 80 vol %, 65 to 75 vol%, or 68 to 72 vol % of the overall composition volume.

In one or more embodiments, the aqueous phase has a high pH in a rangeof from 7 to 14, such as from 8 to 14, from 9 to 14, or from about 10 toabout 14. For example, the aqueous phase pH (“high pH”) may be in arange from 10 to 13.5, 10 to 13, 10.5 to 14, 10.5 to 13.5, 10.5 to 13,11 to 14, 11 to 13.5, 11 to 13, 11.5 to 14, 11.5 to 13.5, 11.5 to 13, or12 to 13.

The high pH is sufficient to provide the solution with a molarconcentration of base (or basic functional groups throughout thesolution) in excess compared to the molar concentration of acidfunctional groups (total organic acid) on the chelating agent that is inthe solution.

In one or more embodiments, the aqueous phase is reactive. “Reactive”means that compounds within the aqueous phase have the ability to reactwith barite particles or barite.

The water of the aqueous phase is not particularly limited and mayinclude but is not limited to fresh water, deionized water, low salinitywater, sulfate water, brine water, and salt water.

The aqueous phase includes a chelating agent. The chelating agent maycontribute to the high pH of the aqueous phase. The chelating agent maybe an organic compound or a salt thereof. The chelating agent includesligands, which may be amines and acid functional groups, such ascarboxylic acid or phosphonic acid. The carboxylic acid may be acarboxymethyl group covalently bonded to an amine. The amine may be twoor more amines that are covalently attached through a carbon chain oftwo or more carbons.

In one or more embodiments, the aqueous phase has one or more chelatingagent selected from the group consisting of DTPA(diethylenetriaminepentaacetic acid or pentetic acid), HEDTA(N-(hydroxyethyl)-ethylenediaminetetraacetic acid), EDTA(ethylenediaminetetraacetic acid), GLDA (glutamic acid-N, N-diaceticacid), HEIDA (hydroxyethyliminodiacetic acid), MGDA(methylglycinetetraacetic acid), EDDS (ethylenediamine-N,N-disuccinicacid), EGTA (ethyleneglycol-bis-(P-aminoethylether)-N,N,N′,N′-tetraacetic acid), NTA(nitrilotriaceticacid), CDTA (cyclohexanediaminetetraacetic acid), AMTP(aminotri-methylene phosphonic acid), E1EDP(1-hydroxy-ethylidene-1,1-diphosphonic acid), citrate, EDG(ethanoldiglycine), and a conjugate base of any of the precedingchelating agents. The chelating agent may act as a base by having anitrogen group, a carboxylate (conjugate base of carboxylic acid), or aphosphate (for example, conjugate base of a phosphonic acid). Examplesof conjugate base of a chelating agent include, but are not limited toK₅-DTPA, DTPA pentapotassium, DTPA pentapotassium hydroxide, glycine, N,N,-bis(2-bis(carboxymethyl)amino)ethyl-pentapotassium salt,pentapotassium-2-[bis(2-[bis(carboxymethyl)amine]ethyl))amino]acetate,K₄-EDTA, and tetrasodium EDTA.

In one or more embodiments, an aqueous base is included in solution witha chelating agent. For example, an aqueous base may be a convertingagent. Although a converting agent has a function of converting BaSO₃,to be described, it may also be configured to obtain a conjugate base ofa chelating agent. These basic compounds may be added to the mixture. Asa non-limiting example, a basic converting agent when added to asolution containing a compound with a carboxylic acid is configured toreact with the carboxylic acid and to form a conjugate base thereof(forming a carboxylate). In one or more embodiments, conjugate basevariant of a chelating agent may be added to the solution.

In one or more embodiments, the chelating agent is in a concentration ofup to 20 weight percent (wt %) of the overall weight of the aqueousphase. The chelating agent may be present at 0.435 to 0.7 moles perliter (M) of the composition.

A converting agent may be included in the aqueous phase. The convertingagent may be an alkaline compound, a base, or both an alkaline and abasic compound. The converting agent includes but is not limited to oneor more of: potassium salts such as potassium hydroxide, potassiumcarbonate, potassium cyanide, potassium formate, potassium nitrate, andpotassium chloride; cesium salts such as cesium carbonate, cesiumformate, and cesium chloride; sodium salts such as sodium hydroxide orsodium carbonate; lithium salts such as lithium carbonate and lithiumformate: ammonium salts such as ammonium carbonate and ammoniumchloride; calcium salts such as calcium chloride; and magnesium saltssuch as magnesium chloride.

The converting agent may be in a concentration of up to 10 wt % of theoverall composition weight. Such a converting agent is soluble in theaqueous phase, and therefore a part of the aqueous phase. The convertingagent may convert BaSO₃ to another barium-based compound, including, butnot limited to, BaCO₃. Conversion of BaSO₃ may facilitate dissolution ofthe barium compound(s) in situ by way of barite interaction with thechelating agent. A suitable converting agent may be present in a rangefrom about 3 to about 10 weight percent (wt %) of the overallcomposition weight, such as from 4 to 10 wt %, 5 to 10 wt %, 6 to 10 wt%, 7 to 10 wt %, 8 to 10 wt %, or 9 to 10 wt %.

The function of the converting agent includes converting barite toanother barium-based compound with greater solubility, as compared towithout the converting agent. However, general solubility of thecomposition may be greater when a chelating agent is included with aconverting agent, as compared to a composition without a chelatingagent.

An oxidizer or enzyme may also be included in the aqueous phase. Theoxidizer or enzyme allows polymers in the filter cake to degrade. Theoxidizer or enzyme may include, but is not limited to, a persulfatesalt, such as potassium persulfate. Generally, an oxidizer may beincluded when polymers are present in an oil-based filter cake. Theoxidizer or enzyme may be in a concentration of up to 10 weight percent(wt %) of the overall composition weight. While biopolymers are nottypically used in oil-based drilling fluids, when there is a biopolymerin the drilling fluid, an enzyme such as alpha-amylase may be used.

Organic Phase

The organic phase (or oil phase) of the well treatment compositionaccording to one or more embodiments herein may include an organicsolvent, an emulsifier, and a wetting agent.

In one or more embodiments, the organic phase is in a volume range offrom 10 to 70 vol % compared to the overall composition volume. Forexample, the organic phase may be in a range of from 10 to 60 vol %, 10to 50 vol %, 15 to 45 vol %, 20 to 40 vol %, 25 to 35 vol %, or 28 to 32vol % of the overall composition volume.

In one or more embodiments, the organic solvent is one or more selectedfrom the group consisting of diesel fuel, oil/hydrocarbon,naphtha/naphthalene, aromatic solvents such as xylene, toluene,N-methylpyrrolidine, D-limonene/Terpene-based solvent, benzene sulfonicacid and derivatives thereof, ethoxylated alcohols, glycosides andderivatives thereof, and heavy naphtha or jet fuel range hydrocarbons.

In one or more embodiments, the organic solvent is in a weight range offrom 20 to 40 wt % of the overall weight of the organic phase. Forexample, the organic solvent may be in a range of from 20 to 35 wt %, 23to 35 wt %, 23 to 32 wt %, 23 to 30 wt %, 25 to 40 wt %, 25 to 35 wt %,25 to 32 wt %, or 25 to 30 wt % of the overall weight of the organicphase.

In one or more embodiments, the emulsifier is in a weight range of from0.5 to 10 wt % of the overall weight of the organic phase. For example,the emulsifier may be in a range of from 0.5 to 5 wt %, 0.5 to 4.5 wt %,0.5 to 4 wt %, 0.5 to 3.5 wt %, 0.5 to 3 wt %, 0.5 to 2.5 wt %, 0.5 to 2wt %, 1 to 5 wt %, 1 to 4.5 wt %, 1 to 4 wt %, 1 to 3.5 wt %, 1 to 3 wt%, 1 to 2.5 wt %, or 1 to 2 wt % of the organic phase.

In one or more embodiments, the emulsifier is in a volume range of from0.5 to 5 volume percent (vol %) compared to the overall compositionvolume. For example, the emulsifier may be in a range of from 0.5 to 4vol %, 0.5 to 3 vol %, 0.5 to 2.5 vol %, 0.5 to 2.0 vol %, 0.5 to 1.9vol %, 0.5 to 1.8 vol %, 0.5 to 1.7 vol %, 0.5 to 1.6 vol %, 1.0 to 1.9vol %, 1.0 to 1.8 vol %, 1.0 to 1.7 vol %, 1.0 to 1.6 vol %, 1.1 to 1.9vol %, 1.2 to 1.8 vol %, 1.3 to 1.7 vol %, or 1.4 to 1.6 vol % of theoverall composition volume.

The emulsifier may be based on a fatty acid, ethanol, and hydrocarbon.The emulsifier promotes water-in-oil emulsions. Fatty acid-basedemulsifiers useful in embodiments herein may have a carboxylic acidfunctional group on a carbon chain of 4 to 28 carbon atoms.Advantageously, the emulsifier according to one or more embodiments maybe used when the aqueous phase has a high pH.

An example of a fatty acid-based emulsifier in embodiments hereinincludes an amidoamine surfactant. A suitable example of such a fattyacid-based emulsifier is SUREMUL®, which is an amidoamine surfactant.SUREMUL® is available from M-I SWACO, LLC (Houston, Tex., USA). SUREMUL®includes: 60-100 wt % fatty acids that are tall-oil, or reactionproducts with diethylenetriamine, maleic anhydride,tetraethylenepentamine and triethylenetetramine (CAS No. 68990-47-6);10-30 wt % 2-[2-(2-butoxyethoxy)ethoxy]ethanol (CAS No. 143-22-6); 5-10wt % C14-C17 alkane hydrocarbons; and 5-10% C10-C14 alkane hydrocarbons.

Other suitable fatty acid-based emulsifiers may be similar toemulsifiers used in oil-based drilling fluids. Thus, the emulsifier mayinclude one or more selected from the group consisting of fatty acidamides or fatty acid ethoxylates consisting of alkylated polyetherchains, tall oil or long-chain alkyl fatty acids and salts thereof,alkyl oligoglycosides combined with fatty acids, fatty alcohol sulfates,alkyl fatty acid polyamide nonionic surfactants, carboxylic acidterminated fatty amine condensates, and starchamine. The emulsifier mayinclude a compound having the formula “R—CO—NH—R′—NH₂” that is an aminoacid amide. Free fatty acids and those corresponding to the generalformula “R′—COOH” may be used as an emulsifier. In the above formulae, Rand R′ are each individually a saturated or unsaturated, branched, orunbranched alkyl group; R′ may contain 11 to 21 carbon atoms in someembodiments.

In one or more embodiments, the wetting agent is in a weight range offrom 0.5 to 10 wt % of the overall weight of the organic phase. Forexample, the wetting agent may be in a range of from 0.5 to 5 wt %, 0.5to 4.5 wt %, 0.5 to 4 wt %, 0.5 to 3.5 wt %, 0.5 to 3 wt %, 0.5 to 2.5wt %, 0.5 to 2 wt %, 1 to 5 wt %, 1 to 4.5 wt %, 1 to 4 wt %, 1 to 3.5wt %, 1 to 3 wt %, 1 to 2.5 wt %, or 1 to 2 wt % of the overall weightof the organic phase.

In one or more embodiments, the wetting agent loading is 0.1 to 5 volumepercent (vol %) of the overall composition volume. The wetting agent maybe from 0.1 to 4 vol %, 0.1 to 3 vol %, 0.1 to 2 vol %, 0.1 to 1.9 vol%, 0.1 to 1.8 vol %, 0.1 to 1.7 vol %, 0.1 to 1.6 vol %, 0.5 to 5 vol %,0.5 to 4 vol %, 0.5 to 3 vol %, 0.5 to 2 vol %, 0.5 to 1.9 vol %, 0.5 to1.8 vol %, 0.5 to 1.7 vol %, 0.5 to 1.6 vol %, 1.0 to 1.9 vol %, 1.0 to1.8 vol %, 1.0 to 1.7 vol %, 1.0 to 1.6 vol %, 1.1 to 1.9 vol %, 1.2 to1.8 vol %, 1.3 to 1.7 vol %, or 1.4 to 1.6 vol % of the overallcomposition volume.

In one or more embodiments, the wetting agent includes amidoamine, fattyacid, or amidoamine and fatty acid. The wetting agent allows emulsionstability to be retained. Emulsion stability is, in part, a measure ofhow long the emulsion remains intact as designed, before separating outor dissipating. Emulsion stability may be manipulated by changing thewetting agent loading.

A suitable example of a wetting agent is SUREWET® which is availablefrom M-I SWACO, LLC (Houston, Tex., USA) and was used in the belowexamples. This may be referred to as an amidoamine surfactant.

As previously mentioned, the composition may include a chelating agent.The chelating agent may be present in an amount up to about 30 volumepercent (vol %), such as up to about 25 vol %, of up to about 20 vol %of the overall well treatment composition. For example, the chelatingagent may be in a range of from about 10 vol % to about 35 vol %, fromabout 15 vol % to about 35 vol %, from about 15 vol % to about 30 vol %,or from about 15 vol % to about 25 vol %, based on the overall volume ofthe well treatment composition.

Other suitable wetting agents include, but are not limited to,amidoamines, long-chain alkyl quaternary ammonium salt cationicsurfactants, treated vegetable oil fatty acids, carboxylic acidterminated polyamides, and oleic acid-based surfactants. The wettingagent may also be a molecule that is made from the condensation reactionbetween unreacted and unmodified fatty acids and polyamine.

Method of Forming the Well Treatment Composition

In one or more embodiments, the method includes mixing the respectivecomponents to form the organic phase and aqueous phase separately. Themethod includes combining the aqueous mixture and the organic mixtureand emulsifying them, thereby forming a water-in-oil emulsion. The orderof mixing is not limited and may include addition of the aqueous phaseto the organic phase, while mixing, in some embodiments.

Methods of Treating a Wellbore

In one or more embodiments, methods for treating a wellbore may includeintroducing the composition into a wellbore as a single stage treatment.The wellbore temperature may be 37° C. or greater (about 100° F.), suchas 93° C. or greater (about 200° F.), 120° C. (about 250° F.) orgreater, 150° C. or greater (about 300° F.), or 180° C. or greater(about 350° F.). The wellbore temperature may be from 120° C. to 180° C.The method may be used as part of a procedure for acid stimulationtreatment.

The method may include introducing a composition according to one ormore embodiments herein into a wellbore, after OBM is used in saidwellbore. The wellbore may be a high temperature gas well, or othersuitable well type. When the composition is introduced into a wellboreahead of a fracturing treatment, such as MSF, it fluidly interacts with(contacts) OBM sludge and filter cake at a target site. The interactionincludes penetrating into the barite-based OBM sludge or filter cakewith the composition. A target site is a location in the wellbore wherefracturing will occur, such as at the frac ports.

A target zone is the general area of the wellbore that fracturing willoccur. For example, where multi-stage fracturing is involved, there aremultiple frac ports across a target zone. One or more individual fracport in this instance is a target site. So, there may be one or moretarget sites in a target zone.

In one or more embodiments, the method treats the target zone or thetarget site and does not treat the entire wellbore. Introducing thecomposition at a target zone or a target site reduces the total volumeof the composition used and the treatment cost, compared to treating theentire wellbore.

In one or more embodiments, coiled tubing or bullheading operation fromthe surface may be used to introduce the composition into the wellbore.Typical pumping units for drilling or coiled tubing operations may beused. In another one or more embodiments, no drill pipe is included.That is, the method introduces the composition into a wellbore after adrilling operation. However, if the method is to be used during drillingoperations, then the method may include spotting the composition in thewellbore using drill pipe and kept for at least about 24 hours, such asfrom 24-48 hours, or up to 24-48 hours. This time period allows forreaction of emulsion with the filter cake.

The treatment pressure during fracturing operations is not particularlylimited and it may be in a range of from, for example, 8,000 to 13,000pounds per square inch (psi) (55 to 90 megapascal (mPa)). The treatmentpressure may also be above about 400 psi (about 3 mPa), about 1000 psi(about 7 mPa), about 2000 psi (about 14 mPa), about 3000 psi (about 21mPa), about 4000 psi (about 28 mPa), about 5000 psi (about 35 mPa),about 6000 psi (about 41 mPa), about 7000 psi (about 48 mPa), or about8000 psi (55 mPa).

The pumping rate may be in a range of from 30 to 40 barrels per minute(bbl/min) (4.7 to 6.4 cubic meters per minute (m³/min)). If coiledtubing is used, then the pumping rate may be in a range of from 2 to 8bbl/min (0.3 to 1.3 m³/min).

Introducing the composition to the target zone in the wellbore enhancesthe solubility of sludge and debris, compared to without introducing thecomposition to the target zone. One or more embodiments of the methodincludes maintaining the wellbore, which includes a period of time thatallows the composition to penetrate the OBM sludge and filter cake.

In one or more embodiments, steps in the method are repeated inmulti-stage fracturing. In this way, the method may be performed at afracture interval individually. Additionally, the method may beperformed in series or in sequence in relation to the multiplefracturing intervals.

Depending on the fracturing operation, maintaining the wellbore mayinclude shutting in the well (such as at the wellhead). When a shut-inprocedure is used, the composition that was introduced has time to actupon the OBM sludge and filter cake and a shut-in time may be from about2 hours to about 24 hours. However, there may be no shut-in time for thecomposition, as one or more embodiments of the method includes using thecomposition as breakdown fluid during fraccing operations.

In general, a break down fluid such as 26 wt % HCl may be introducedfirst, followed by the composition of one or more embodiments, mutualsolvent pill, then fraccing fluids.

For example, in a general process of hydraulic fracturing operations,break down fluids may initially be introduced to initiate a fracture,then linear and cross-linked fluids with proppants are introduced toallow the fracture to close on the proppant particles (i.e. packed withproppant particles). Thus, fracture permeability is higher thanreservoir permeability. Typical breakdown fluids include but are notlimited to 26 wt % HCl. In one or more embodiments, both 26 wt % HCl andthe composition for fracture stages are presented for those stages thatcannot be initiated with 26 wt % HCl or other typical breakdown fluid.

The well treatment composition may remove up to 40 to 50 wt % ofdeposited OBM sludge and filter cake having barite particles, such as atleast about 40 wt % or at least about 50 wt %. This deposit removal issufficient to facilitate fracture initiation during MSF completion. Insome instances, the well treatment composition may remove greater than50 wt % of the deposited OBM sludge and filter cake having bariteparticles. In other instances, the well treatment composition may removeabout 20 vol % or more, 25 vol % or more, 30 vol % or more, 35 vol %, ormore 40 vol % or more, 45 vol % or more, or 50 vol % or more of thedeposited OBM sludge and filter cake having barite particles.

According to one or more embodiments, the amount of the well treatmentcomposition needed to dissolve 1 gram (g) of OBM sludge and filter cakehaving barite particles may be about 10 milliliters (mL) (10 mL/g), suchas about 10 mL/g or greater, or 10 mL/g or greater.

When the step of maintaining the wellbore is complete, fracture stageinitiation may proceed at a port (perforation), which was previouslydamaged by OBM sludge and filter cake having barite particles.

One or more embodiments of the method includes a fracturing step. Thefracturing step may be hydraulic fracturing. In one or more embodiments,when multi-stage fracturing is used as the fracturing step, the type offracturing will be hydraulic or propped fracturing.

The method of the present disclosure is applicable in numerousenvironments. The method can be used to remove barite in sludge orfilter cake produced from drilling, production, completion, workover, orstimulation activity, either produced intentionally or unintentionally.It can be used in screen-only completions and gravel pack completions,an open hole and a cased hole, vertical and highly deviated wells;single-application soak or circulating fluid in which the well treatmentcomposition of the present disclosure also serves as a carrier fluidfor, e.g., a gravel pack operation; in conjunction with a gelling agentor viscoelastic surfactant or alone, and with a variety of clean-uptools. More particularly, the composition and methods of the presentdisclosure may be used whenever it is desirable to remove a barite insludge or filter cake from a wellbore or near-wellbore region in aformation, regardless of whether the sludge or filter cake is producedduring drilling or during other post-drilling operations (e.g.,fluid-loss control, gravel pack operation, fracturing, matrix acidizing,etc.).

Regarding the high pH of the composition and interaction between barite,where chelating agents such as EDTA and DTPA are at a pH above about 10,such as pH 10 to 12 or above, a fully deprotonated species maypredominate, with carboxylates rather than acids. For EDTA, thepredominant species may be EDTA⁴⁻ with HEDTA³⁻ present. For DTPA, thepredominant species may be DTPA⁵⁻ with HDTPA⁴⁻ present. A reactionbetween Ba²⁺ (in barite, BaSO₄) and either EDTA⁴⁻ or HEDTA³⁻ may produceBaEDTA²⁻. That is, HEDTA³⁻ may release a proton upon complexation withBa²⁺ at high pH. Similarly, either DTPA⁵⁻ or HDTPA⁴⁻ may produceBaDTPA³⁻ upon complexation with Ba²⁺ at high pH. HDTPA⁴⁻ may release aproton during the reaction. Thus, when using the composition and methodof one or more embodiments, a similar barium chelate may be obtained inthe case of EDTA or DTPA, respectively.

In addition to barite itself, a plethora of barium complexes may existdownhole. When a chelating agent of one or more embodiments of thecomposition (not limited to EDTA or DTPA) contacts barium or bariteparticles at high pH, the chelating agent may form a chelation complexwith these various barium or barite particles. These chelation complexesserve a similar purpose as an ideal barium chelation complex, aspreviously presented.

Further, the chelating agent in the composition at high pH may stripalloys and salts of barium, where those alloys originate from barite orbarite particles.

Without wanting to be bound by theory, it is predicted that the methodincludes chelation of barium at high pH, even when diverse types ofmolecules originating from barite are present. Diverse types ofmolecules originating from barite may include but are not limited tobarium alloys and minerals. These compounds may include but are notlimited to Ba(M)SO₄ (where M is a metal), BaCO₃ and BaCl₂. These diversetypes of molecules may be removed from the OBM sludge and filter cake bythe composition and method of one or more embodiments.

In one or more embodiments, the water-in-oil emulsion traps a bariumchelate complex in the dispersed (aqueous) phase, surrounding it withthe oil phase. Advantageously, this chelation of metal and trapping oforganometallic (barium chelate complex) in the water-in-oil emulsioneffectively removes the barium or barite particle from the reactionequilibrium at the target site. This is different than, for example,removing a barium or barite particle with aqueous solution alone (orwith an oil-in-water emulsion, a two stage treatment, or a similarconventional method of barite removal). That is, conventional methods ofsequestering or removing barite particles allow barite particles toremain in fluidic contact through solution with the OBM sludge andfilter cake.

EXAMPLES

The following examples include a showing of the solubility of oil-basedmud (OBM) sludge or filter cake having barite using the composition ofone or more embodiments. The examples do not include field trials.

Oil-Based Mud Sludge Having Barite

The samples of oil-based mud sludge having barite (or barite-based OBMsludge), also called filter cake having barite, were synthesized in thelab. These samples may include the following: bicarbonate at 9,882milligrams per liter (mg/L), carbonate from 65,520 to 68,580 mg/L,barium from 4,300 to 6,624 mg/L, calcium at 4,406 mg/L, chloride from14,723 to 18,129 mg/L, magnesium at 792 mg/L, potassium from 14,4156 to14,7968 mg/L, sodium from 4,600 to 7,003 mg/L, strontium from 13 to 33mg/L, sulfate from 368 to 453 mg/L, and a specific gravity at 60° F. of1.224 to 1.235 grams per milliliter (g/mL) (or grams per centimetercubed (g/cc)).

The samples of OBM sludge having barite were analyzed by XRF/XRD,initially dried prior to analysis. Composition data is shown in Tables 1to 3.

TABLE 1 Molecular Composition of Oil-Based Mud Sludge having BariteCompound Weight percent Barite (BaSO₄) 73 Calcite (CaCO₃) 8 Dolomite(CaMg(CO₃)₂) 10 Quartz (SiO₂) 6 Halite (NaCl) 3 Microcline (KAlSi₃O₈)Trace

TABLE 2 Elemental Composition of Oil-Based Mud Sludge having BariteElement Weight percent Barium (Ba) 43 Sulfur (S) 10 Calcium (Ca) 5.3Silicon (Si) 2.7 Chlorine (Cl) 1.6 Magnesium (Mg) 1.4 Sodium (Na) 1 Iron(Fe) 0.2 Cesium (Cs) 0.1 Aluminum (Al) 0.01

TABLE 3 Ionic Concentrations of Oil-Based Mud Sludge having Barite,initially dried prior to analysis. Ion Concentration (mg/L) Bicarbonate9,882 Carbonate 65,520 to 68,580 Barium 4,300 to 6,624 Calcium 4,406Chloride 14,723 to 18,129 Magnesium   792 Potassium 144,156 to 147,968Sodium 4,600 to 7,003 Strontium 13 to 33 Sulfate 368 to 453

In the Examples, the specific gravity of the oil-based mud sludge orfilter cake having barite (initially dried prior to analysis) at 60° F.is 1.224 to 1.235 g/mL (or g/cc).

Example 1

A well treatment composition was prepared based on a 70/30 volumefraction between aqueous phase and the organic phase. A glass containerwas used to mix the organic phase with: 1.5 vol % of the emulsifier(SUREMUL®), 1.5 vol % of the wetting agent (SUREWET®), and 27 vol % ofdiesel fuel. In a separate glass container, the aqueous phase ofchelating agent was prepared. Although a typical aqueous phasecomposition may include water, DTPA, and converting agent, the aqueousphase of Example 1 included water and BaraDis™ at a ratio such that thechelating agent DTPA (pentetic acid or diethylenetriaminepentaaceticacid) was present at about 20 vol % (of the overall composition volume).It is noted that BaraDis™ as commercially available includes convertingagent and cellulose/sucrose enzymes. While the enzyme is present in thisexample, due to the nature of the sludge being tested, it is unlikelythat the enzymes had an effect on the present test results. BaraDis™ isavailable from Smart Energy Support Services Co. Ltd. (SESS) (formerlyknown as Modern National Chemicals). A funnel was used to add theaqueous phase into the organic phase, to obtain a mixture. The mixtureof aqueous and organic phases was stirred to obtain the water-in-oilemulsion. The water-in-oil emulsion also included 10 to 15 vol %converting agent (potassium carbonate).

DTPA in BaraDis™ is estimated to include about 20 wt % DTPA (such asK₅-DTPA) in the BaraDis™ solution, or about 0.4 to about 0.6 mol/L ofDTPA in the overall volume of the aqueous phase.

Conductivity Test

Conductivity tests on the water-in-oil emulsion of Example 1 showed zeroconductivity. Thus, the structure of the water-in-oil emulsion wasconfirmed and proven to have good initial stability.

Drop Test

In the drop test, a drop of the water-in-oil emulsion of Example 1 wasadded to a large volume of water. The test proceeded by observing thesingle drop over a period of about 8.5 hours. Results of the drop testindicated 7 to 8 hours stability was reached when 1.5 wt % emulsifieragent was used along with 1.5 wt % of wetting agent. After 7 to 8 hours,the water-in-oil emulsion of Example 1 began to break apart in thewater. In the drop tests, 18 hours of emulsion mixing was used to reach7 to 8 hours of stability.

Obtained results from drop test revealed that emulsion stability can bemanipulated by changing wetting agent loading.

Stability Test

The water-in-oil emulsion of Example 1 showed stability for 96 hours ormore (no phase separation occurred when the solution remained stagnant(no mixing)). The stability test was conducted at room temperature byplacing a quantity of the emulsion of Example 1 in a vial and observingthe emulsion over a time period of 96 hours.

In a negative control test for stability, a demulsifying agent was addedto the water-in-oil emulsion of Example 1. Before adding thedemulsifying agent, the concentrations of all additives were the same asthe stability test. Results of the negative control test showed that thewater-in-oil emulsion of Example 1 is immediately broken by adding 0.6vol % demulsifying agent. In this negative control test, thedemulsifying agent was “W054” (available from Schlumberger, USA) and ismainly composed of methanol, oxyalkylated alkyl alcohol, heavy aromaticnaphtha, and quaternary ammonium compound.

Solubility Test

Multiple solubility tests were performed using the water-in-oil emulsionof Example 1. These tests investigated the ratio between organic solventand chelating agent, and the additives that create a stable emulsion.

To demonstrate the dissolution of a mixture of barite and organicmaterial, solubility tests were conducted on samples of the OBM sludgehaving barite (or barite-based filter cake, as it is dried OBM sludgehaving barite). The samples to be tested were prepared in a laboratory.The water-in-oil emulsion of Example 1 was used to run stability testsat high temperature (154° C. in this example) and room temperature (21°C. in this example).

The OBM sludge mass to Example 1 emulsion volume ratio was 1:10, or 1gram (g) of sludge per 10 milliliters (mL) of water-in-oil emulsion.Table 4 shows the solubility test results at high temperature and roomtemperature.

TABLE 4 Solubility Tests. High Room Sample Name Temperature TemperatureSolvent High pH DTPA/Diesel Ratio (filter cake mass in 1:10 1:10 gramsto emulsion volume in cubic centimeters) Temperature, ° C. (° F.) 154(310) 21 (70) Soaking Time, hours 24 24 wt % Dissolved   53%   28%

The results of Table 4 show that barite-based OBM sludge (barite-basedfilter cake) solubility increased (increased wt % dissolved) as thetemperature increased from room temperature to high temperature.

In the high temperature solubility experiment at 154° C. (310° F.) for24 hours, the filter cake was hardened with large visible cracks in thesurface. Further, some large pieces of the filter cake were broken offfrom the main filter cake, without intervention.

In the room temperature solubility experiment at 21° C. (70° F.) for 24hours, the filter cake was hardened with many mudcracks (desiccationcracks) compared to the high temperature solubility experiment. However,the filter cake appeared to remain intact, with no pieces broken offfrom the main filter cake.

Comparative Example 1

An OBM sludge sample was treated with DTPA-based fluid at 149° C. (300°F.) and showed 20% solubility, as shown in Table 5.

TABLE 5 Solubility of barite/oil-based mud sludge in comparativeexample, with chelating agents (without emulsion according to one ormore embodiments). DTPA-based, Compound 5-10% mutual solvent (two-stage)Solubility, wt % about 60 pH   10 to 12.5 Density change, g/cm³ 1.19 to1.13 Soaking time, hours 16 Temperature, ° F. (° C.) 310 (154) Solid(grams):liquid 1:10 (cubic centimeter) ratio

Table 6 shows the composition of the OBM sludge sample. However, thesludge is not intended to be reproduced, as the sludge is normallyobtained from the field. The sludge is meant to represent that whichwould be obtained from a fraccing operation, when frac initiation failswith an inorganic composition (which may include some organic material)similar to the one below.

Units for Table 6 are as follows: barrel (bbl) (1 bbl=0.16 m³), pound(lb) (1 lb=0.454 kg), second (sec), minute (min), pound per cubic feet(lb/ft³) (1 lb/ft³=16 kilogram per cubic meter (kg/m³)), and pound per100 square feet (lb/100 ft²) (1 lb/100 ft²=4.88 kilogram per 100 squaremeter (kg/100 m²)).

TABLE 6 Oil-based drilling fluid general recipe. Material/PropertyFunction Value Unit Property Value Unit Water 0.15-0.17 bbl Density83-95 lb/ft³ diesel Base fluid  0.6-0.67 bbl Yield 12-22 lb/100 Pointft² CaCl₂ Weighting agent 16-18 lb Gels,  8-11 lb/100 10 sec ft²Amine-treated lignite Polymeric fluid loss reducer  8-12 lb Gels, 12-16lb/100 10 min ft² Organophilic clay or Viscosifier 6-9 lb Organicsurfactant wetting agent/emulsifier 1.2-8   lb Organic surfactantemulsifier 0..35-4    lb surfactant Oil wetting agent 0.3-4   lbSynthetic fluid Rheological properties enhancer 0.25-2   lb Lime pHcontrol/calcium source 5-8 lb Calcium Carbonate, d-25 Bridging agent 5lb Calcium Carbonate, d-50 Bridging agent 5 lb Sized graphiteLost-circulation/seepage agent 2 lb Sized graphite-fineLost-circulation/seepage agent 4 lb Barium sulfate, barite Weightingagent 200-240 lb

These examples show that the chelating agent (DTPA) itself dissolvedabout 20 wt % of the OBM sludge having barite, and that the compositionof one or more embodiments including the chelating agent (DTPA)dissolved greater than 40 wt % of the oil-based mud sludge based onbarite.

The mass removed (wt %) by from the filter cake includes barite. In oneor more embodiments, the spent composition includes 4,000 to 6,000milligrams per liter (mg/L) of barium (after reaction with the sludge).

In one or more embodiments, the total dissolved solids after reaction ofchelating agent with the barite/oil-based mud sludge was about 338,000to 349,000 milligrams per liter (mg/L).

As used here and in the appended claims, the words “comprise,” “has,”and “include” and all grammatical variations thereof are each intendedto have an open, non-limiting meaning that does not exclude additionalelements or steps.

“Optionally” means that the subsequently described event orcircumstances may or may not occur. The description includes instanceswhere the event or circumstance occurs and instances where it does notoccur.

When the word “approximately” or “about” are used, this term may meanthat there can be a variance in value of up to ±10%, up to ±5%, up to±2%, up to ±1%, up to ±0.5%, up to ±0.1%, up to ±0.01%, up to +10%, upto +5%, up to +2%, up to +1%, up to +0.5%, up to +0.1%, up to +0.01%, upto −10%, up to −5%, up to −2%, up to −1%, up to −0.5%, up to −0.1%, orup to −0.01%.

Ranges may be expressed as from about one particular value to aboutanother particular value, inclusive. When such a range is expressed, itshould be understood that another one or more embodiments is from theone particular value to the other particular value, along with allparticular values and combinations thereof within the range.

Although only a few example embodiments have been described in detail,those skilled in the art will readily appreciate that many modificationsare possible in the example embodiments without materially departingfrom this disclosure. All modifications of one or more disclosedembodiments are intended to be included within the scope of thisdisclosure as defined in the following claims. In the claims,means-plus-function clauses are intended to cover the structurespreviously described as performing the recited function and not onlystructural equivalents, but also equivalent structures. It is theexpress intention of the applicant not to invoke 35 U.S.C. § 112(f) forany limitations of any of the claims, except for those in which theclaim expressly uses the words ‘means for’ together with an associatedfunction.

While one or more embodiments of the present disclosure have beendescribed with respect to a limited number of embodiments, those skilledin the art, having benefit of this disclosure, will appreciate thatother embodiments can be devised, which do not depart from the scope ofthe disclosure. Accordingly, the scope of the disclosure should belimited only by the attached claims.

What is claimed:
 1. A method, comprising: introducing a composition thatis a water-in-oil emulsion into a wellbore as a single stage treatmentsuch that it fluidly interacts with an oil-based mud sludge or a filtercake at a target zone, wherein the composition does not include a mutualsolvent; wherein the water-in-oil emulsion has an organic phase and anaqueous phase, the organic phase comprising an organic solvent, anemulsifier, and a wetting agent, and the aqueous phase comprising waterand a chelating agent, wherein the oil-based mud sludge or the filtercake comprises barite; wherein the target zone has a deposit of theoil-based mud sludge or the filter cake; maintaining the wellbore byshutting-in the wellbore and allowing the composition to penetrate theoil-based mud sludge or the filter cake in a target zone, therebyallowing the composition to remove a portion of the oil-based mud sludgeor the filter cake; and hydraulic fracturing the wellbore.
 2. The methodof claim 1, wherein the target zone is a fracture port.
 3. The method ofclaim 1, wherein the method is repeated in multi-stage fracturing. 4.The method of claim 1, wherein the aqueous phase has a pH in a range offrom 7 to
 14. 5. The method of claim 1, wherein the aqueous phase has apH in a range of from 10 to
 14. 6. The method of claim 1, wherein thetarget zone of the wellbore has a temperature of from 120° C. to 180° C.7. The method of claim 1, wherein the target zone of the wellbore has apressure of above about 400 psi.
 8. The method of claim 1, wherein atleast about 40 wt % of the oil-based mud sludge or the filter cake isremoved from the wellbore.
 9. The method of claim 1, wherein at leastabout 50 wt % of the oil-based mud sludge or the filter cake is removedfrom the wellbore.
 10. The method of claim 1 comprising allowing thecomposition to penetrate the wellbore for at least about 24 hours. 11.The method of claim 1, wherein the water-in-oil emulsion has a viscosityof 80 to 200 cP at 20 to 30° C.
 12. The method of claim 1, wherein theorganic phase further comprises ethanol and a hydrocarbon.
 13. Themethod of claim 1, wherein the organic phase is from 10 to 70 vol % ofan overall composition volume.
 14. The method of claim 1, wherein theaqueous phase is from 30 to 90 vol % of an overall composition volume.15. The method of claim 1, wherein the emulsifier is a fatty acid-basedemulsifier.
 16. The method of claim 1, wherein the emulsifier is in arange of from 0.5 to 5 vol % of an overall volume of the organic phase.17. The method of claim 1, wherein the organic solvent is one or moreselected from the group consisting of diesel fuel, oil/hydrocarbon,naphtha/naphthalene, xylene, toluene, N-methylpyrrolidine,D-limonene/Terpene-based solvent, benzene sulfonic acid and derivativesthereof, ethoxylated alcohols, glycosides and derivatives thereof, andheavy naphtha or jet fuel range hydrocarbons.
 18. The method of claim 1,wherein the organic solvent is in a range of from 20 to 40 wt % of anoverall weight of the organic phase.
 19. The method of claim 1, whereinthe wetting agent is one or more selected from the group consisting ofan amidoamine, an alkyl quaternary ammonium salt cationic surfactant, atreated vegetable oil fatty acid, a carboxylic acid terminatedpolyamide, and an oleic acid-based surfactant.
 20. The method of claim1, wherein the wetting agent is in a range of from 0.5 to 5 vol % of theoverall composition volume.